In 2015, SolarCity, now Tesla, filed an antitrust lawsuit against Salt River Project, claiming the Arizona utility’s $50-per-month demand charges for solar net-metered customers constituted an unlawful use of its monopoly powers to stifle competition.
The case garnered national attention for its unusual approach to fighting the rise of demand charges, fixed charges and other costs for solar-equipped customers via antitrust law, and its potential implications for ratemaking policy across the country. But before that case can go forward, the U.S. Supreme Court has to decide a separate legal issue -- whether SRP is or isn’t immune from antitrust law as a publicly owned utility.
A U.S. District Court judge in Arizona and the 9th U.S. Circuit Court of Appeals ruled that it isn’t. But Salt River appealed to the high court in September, setting up the legal showdown to come during oral arguments set for March 19th.
This week, a host of groups filed amicus briefs, outlining the complicated issues that could determine whether SolarCity’s original challenge will or won’t see it’s day in court.
“There are a ton of different battles in this one Supreme Court case,” said Jean Su, associate conservation director for the Center for Biological Diversity and the author of its amicus brief in the case. “On the one hand, you have consumers and environmentalists going against utilities -- and you also have solar versus fossil fuels.”
This argument is summed up in her organization’s filing, which cited “both ever-increasing greenhouse gas concentrations -- currently at more than 400 parts-per-million -- and the negative impacts of fossil fuel extraction and combustion on public health, wildlife, and the environment,” as justification for allowing SolarCity’s case to go forward.
“But you also have small business versus big business -- a bunch of small businesses came out saying they don’t want to be bullied,” she said, referring to a brief from the National Federation of Independent Business, stating that a decision against SolarCity could limit its members from seeking antitrust claims against quasi-public market participants in the future.
“And then you have states versus feds,” she said. While the U.S. Department of Justice filed an amicus brief supporting the use of antitrust law, groups representing state and local governments filed a brief stating their concern that a decision removing SRP’s immunity could open them up to antitrust lawsuits as well, and expose them to “enormous costs and risks.”
SRP has claimed that it’s protected against lawsuits like SolarCity’s under the “state-action immunity” doctrine, which holds that because it’s given its authority to set prices by the state, it’s not subject to federal antitrust law. But according to Su and the other environmental groups filing briefs before the court, SRP’s unusual structure ought to exempt it from this immunity.
“SRP’s voting structure is only available to people who own real estate in that jurisdiction,” she said, with larger landholders receiving more voting power. That might have made sense in 1903, when it was founded as an irrigation and hydropower project. But SRP’s service territory now hosts some of the most highly populated parts of the state, including the Phoenix suburbs of Scottsdale, Mesa and Tempe and much of the rest of Maricopa County.
That urban population is increasingly shut out of decision-making at the utility, Su said. For example, “if you rent, you’re not eligible. That eliminates 30 percent of all ratepayers, on average.”
The Supreme Court has in fact ruled in the 1981 case of Ball v. James that SRP is “more a for-profit entity than a public entity,” she said. But whether public entities similar to SRP are subject to this kind of immunity have a murkier legal history, she said, with three U.S. Circuit Court decisions against and two for it -- a situation known as a “circuit split,” which justifies a Supreme Court review.
The Supreme Court is expected to issue a decision this summer. Su and her cohorts hope to see it uphold the 9th Circuit decisions, and send Salt River back to District Court to face SolarCity’s antitrust claims. There, it will face questions about whether its demand charge regime is an illegal use of its monopoly power to stifle private-sector competition from rooftop solar -- a complicated legal issue that’s based both on intent and real-world effects of its policy, she said.
"The scariest option is that public power entities like SRP can totally use state action immunity and be exempt from antitrust law," via a Supreme Court decision that upholds its claim directly, said Su.
There’s no doubt that SRP’s demand charges have had a real-world effect. SolarCity reported a 96-percent drop in sales after the plan was introduced. And GTM Research data shows that solar installations in SRP territory “cratered” in the second half of 2015, as GTM Research solar analyst Cory Honeyman put it, and have remained a shadow of their former selves since then.
“Even with some companies saying that they can still make solar work in the territory, with things like storage or other demand-management strategies, the market in SRP still is not close to the capacity it was prior to the demand charges,” GTM Research solar analyst Allison Mond said.
In the meantime, SRP has issued an RFP for 100 megawatts of renewables, with a minimum project size of 25 megawatts. It’s also tapped into the falling cost of batteries for grid-scale energy storage, with a 20-year power-purchase agreement for 20 megawatts of lithium-ion batteries alongside the same amount of new solar PV.
But for small residential and solar customers, the demand charges, which apply only to solar customers, are still too high for the solar-storage economics to work out, Honeyman said.
SRP’s demand charges are an extreme example of a rising trend. Utilities have proposed demand charges in states including Arizona, California, Massachusetts, Oklahoma, Texas, Ohio and North Carolina, with varying degrees of success.
In Arizona, investor-owned utility Arizona Public Service tried to bring mandatory demand rates to all residential and small-commercial customers, but was fought back by consumer and solar advocates, and ultimately agreed to a settlement that made the rate purely optional. In January, Massachusetts utility Eversource received regulatory approval for a mandatory demand charge for residential solar customers, and has since been challenged in court.
All of these new rates are meant to serve the higher cause of balancing the costs and benefits of customer-owned solar between those that have it and those that don’t. Demand charges, in their various forms, are commonly based on a customer’s peak usage -- the moment they’re putting their maximum share of stress on the grid -- as a way to more accurately link prices to costs.
“Demand charges are intended to more equitably compensate for grid usage, since infrastructure is built for capacity,” MJ Shiao, GTM Research head of Americas. But he cautioned that SRP’s example shows that, “if they're not carefully considered or calculated, demand charges can have a strongly negative impact on local distributed generation.”
Solar company SunPower is bracing itself for the impact of the Trump administration’s recently issued tariffs on imported solar cells and modules.
The company -- based in Richmond, Calif. and majority-owned by French oil giant Total -- could be hit harder than most in the U.S. solar sector due to its international manufacturing base in the Philippines and Mexico, a well as its high-efficiency solar panels with advanced technology that takes on a price premium.
While seeking an exclusion from the import tariff, SunPower said in its fourth-quarter earnings call last week that it is already experiencing negative effects on its business as a result of the increased costs from the Section 201 trade case.
The import tariffs “have delayed certain 2018 projects and made other projects uneconomical,” said SunPower CEO Tom Werner on the call. Werner said the company has already implemented a hiring freeze and has reduced some discretionary programs.
SunPower released additional information on its cost-cutting efforts today in an SEC filing, including plans to reduce non-manufacturing headcount by 150-250 employees by mid-2019, representing approximately 3 percent of the company’s global workforce. SunPower expects to incur restructuring charges totaling $20 million to $30 million, largely related to severance benefits and real estate lease terminations.
Last month, the company announced that it had pre-emptively stopped a planned $20 million investment that would have been used to expand manufacturing of the company’s next-generation solar cells. The move led to the loss of hundreds of new jobs that would have been created in California and Texas, said SunPower.
Werner estimated on last week's earnings call that the impact of the tariff on SunPower’s earnings could be somewhere between $50 million to $100 million. In response to a question from an analyst, Werner explained: “[T]o scale the impact of 201 for 2018, it depends on mix, of course, and the safe harbor material and all those sorts of things, but the impact on EBITDA is between $50 million and $100 million.”
After months of speculation, last month the Trump administration issued the new 30 percent year-one tariff on imported solar cells and modules. The tariffs decline over a four-year period and the first 2.5 gigawatts of imported cells are excluded in each of those four years.
While the tariff could give a boost to solar companies that manufacture cells and modules in the U.S., it will raise costs for companies making solar cells abroad, as well as companies relying on low-cost imports of solar cells and modules made outside of the U.S.
GTM Research predicts that the price of solar panels will rise by 10 cents a watt on average in the first year of the tariff. At the same time the U.S. solar industry is expected to see a net reduction in installations of 11 percent this year.
As GTM Research's MJ Shiao put it, the tariff will have a “meaningful but not destructive impact" on solar installations in the U.S.
The U.S. utility-scale solar market could see the largest decline, by close to 5 gigawatts, over the next five years as a result of the tariffs. SunPower has a large utility-scale solar power plant development business, which it is trying to move away from.
SunPower could avoid the negative effects of the tariff on its business if it can manage to convince the Trump administration to give it an exemption. Companies can apply to have certain solar products exempt from the import tariff.
SunPower said in its earnings call that it should be exempt because only it can make “a copper-plated, interdigitated back contact solar cell.” With the exclusion, the company said it would be able to invest in further research and development of that technology.
From “what we've read so far, [it] suggests that we're a good fit for exclusion. We’ll see,” said Werner.
Werner also said that if the company receives an exemption, it would likely be able to recapture the majority of the lost business.
Companies need to file for exemptions with the Office of the U.S. Trade Representative. Details of the exemption process were announced on February 14 (the day SunPower held its earnings call), and companies have 30 days to file for the exclusion. There will be another 30 days of a public comment period, and then the administration will make its decisions.
However, in case SunPower does not receive an exclusion, the company is already looking to cut costs. SunPower has also been in the process of streamlining its business and improving liquidity before the tariffs were announced to address fluctuating global solar markets.
In the run-up to the exemption decision, SunPower said it has been building up safe-harbor inventory in the U.S. It’s got at least three months' worth of tariff-free solar panels stocked. At the same time, the company has been looking to grow its international business.
One of the strategies that SunPower has used to create more liquidity has been to sell off assets. That started with the sale of SunPower’s stake in YieldCo 8point3.
The company also plans to sell its leases, which include 45,000 contracts that deliver monthly payments from 400 megawatts of rooftop solar panels. Werner said last week that SunPower hopes to close the lease sale “in the first half of this year,” and that it could generate “$200 million in cash.”
SunPower plans to use the proceeds from the lease sale to help pay for a $300 million convertible bond due in June. However, the leases have been estimated to hold long-term value of $1.4 billion, and SunPower was also forced to take a non-cash charge of $474 million in the fourth quarter.
Overall, Wall Street didn’t take kindly to SunPower’s earnings and cost-cutting news last week. The company’s stock dropped close to 5 percent on earnings day, though it has since rebounded.
For the fourth quarter of 2017, SunPower generated revenue of $658.1 million, down from the $1.02 billion it generated in the fourth quarter of 2016. At the same time, the solar company lost $558.7 million in the recent fourth quarter, which was more than double the loss it had of $275.1 million in the fourth quarter of 2016.
For the full year SunPower generated $1.87 billion in revenue in 2017, down from the $2.56 billion it generated in 2016. Its net loss was $851.2 million this year, which was significantly higher than its net loss of $471.1 million in 2016.
The analysts at Baird Equity Research described SunPower as facing “a transition year.”
“Although 2018 will be a transition year, we are not downgrading shares as we believe SPWR is effectively managing industry and regulatory headwinds while it ramps P Series and NGT production,” wrote Baird analysts.
Bright spots for SunPower continue to be its commercial and residential solar development businesses, and its increased use of energy storage for commercial customers. SunPower reported a 30 percent solar-plus-storage attachment rate with a project pipeline valued at $60 million.
BP's latest Energy Outlook sees peak oil on the horizon for the first time -- driven by the rise of shared and autonomous electric vehicles.
Under the Evolving Transition (ET) scenario, which assumes that policies and technology continue to evolve at a speed similar to that seen in recent past, oil demand slows and eventually plateaus in the late 2030s.
At the same time, the total passenger vehicle fleet will nearly double to 2 billion cars by 2040 -- including more than 320 million EVs, up from roughly 3 million today. This represents a significant increase over previous forecasts.
In the ET scenario, there are nearly 190 million electric cars by 2035, which is nearly double the 100 million EVs forecast in the base case of last year’s Energy Outlook. The stock of electric cars is projected to increase by an additional 130 million in the subsequent five years, reaching the total of 320 million cars by 2040.
Several other energy research groups have upped their EV forecasts in recent years. However, BP's latest projection ranks among the most ambitious.
By the end of BP's forecast period, the number of EVs will have grown to around 15 percent of the total car fleet. But the number of EVs doesn't tell the whole story. When it comes to understanding the future energy mix, it also depends on how vehicles are used.
In a divergence from previous reports, BP examined vehicle kilometers traveled while powered by electricity to account for the combined impact of vehicle electrification, shared mobility and autonomous driving. EVs are expected to supply the vast majority of shared, autonomous transportation due to lower maintenance costs and lower emissions profile.
Because they're used with much higher intensity, EVs will account for 30 percent of passenger vehicle kilometers by 2040, up from just 2 percent in 2016. According to BP chief economist Spencer Dale, the average EV will be driven about 2.5 times more than an internal combustion engine (ICE) car.
"This higher share reflects the importance of EVs in shared mobility, where the lower costs per km of EVs make them more competitive than ICE cars, as shared-mobility cars are used much more intensively," the report states. "In particular, the sharp fall in the cost of car travel associated with fully autonomous cars, which start to become available in the early 2020s, leads to a substantial increase in shared mobility (and use of EVs) in the 2030s."
Increasing prosperity in developing countries is expected to more than double the demand for travel by passenger cars over the coming decades, under the ET scenario. But increased vehicle fuel efficiency stemming from tighter emissions standards, combined with the trend toward electrification and shared mobility, will largely offset the impact of increased car travel on liquid fuel demand.
By the end of the forecast period in the Energy Outlook, these changes will actually begin to make a dent in oil use. Liquid fuel demand from the car fleet is forecast to hit to 18.6 million barrels per day in 2040, down slightly from 18.7 million barrels per day in 2016.
Oil will continue to dominate across all segments of the transportation sector through 2040, despite the rise of alternatives.
Demand for oil and other liquid fuels, including biofuels, grows over much of the forecast period. However, it gradually slows in the later years of the forecast, and by the late 2030s BP expects oil demand to decline for the first time.
Efficiency gains in passenger and freight transport, as well as aviation and marine, will increase energy use in transport by only 25 percent over the forecast period, which is far less than the 80 percent increase during the previous 25 years.
The non-combusted use of oil and gas, while currently accounting for just 10 percent of global demand, will become the largest contributor to oil and gas growth from 2030 on. Oil majors, including BP, Shell and Total, are banking on sustained petrochemical growth. But like transportation, this sector also faces the possibility of disruption.
BP notes that increasing environmental pressures could dampen demand for some petrochemical products, particularly single-use plastics. Strict new policies on plastics consumption could curb oil demand by as much as 2 million barrels per day, which is roughly the same impact forecast from EVs.
In Wood Mackenzie's forecast for a carbon-constrained world, petrochemical feedstock demand growth is positive in the near term, but slows markedly to 2035.
Greater prosperity, particularly in developing economies, will continue to drive growth in energy demand. By 2040, global energy consumption is set to increase by roughly one-third.
But, as in the transportation sector, overall growth will be slower than in previous years. Global energy demand in the ET scenario grows at around 1.3 percent over the Energy Outlook period, down from over 2 percent in the previous 20 years.
"This slowing in demand growth is largely due to energy intensity (energy used per unit of GDP) falling more quickly than in the past: global GDP more than doubles over the [forecast period], but energy consumption increases by only 35 percent," the report states.
Economies will become more efficient as they continue to electrify over the next two decades. At the same time, they'll become increasingly powered by renewables.
BP revised its renewable energy forecast up in the latest Energy Outlook, projecting that renewables will increase their share of total power generation from 7 percent today to around 25 percent by 2040. Renewables will be the fastest-growing power resource over that period -- and any similar period. "The closest parallel is the rapid build-up of nuclear power in the 1970s and 1980s," the report states.
In 2035, global solar power is more than 150 percent higher than in the base case of the 2015 Energy Outlook. This reflects solar costs falling faster than anticipated. BP now projects solar will be widely competitive by the mid-2020s -- 10 years earlier than previously expected.
As renewable energy sees greater adoption, China and other parts of the developing world will take over from the EU as the primary engine of growth. Over the forecast period, China will add more renewables than the entire Organisation for Economic Cooperation and Development (OECD) countries combined.
Looking beyond power generation to primary energy consumption, natural gas will grow rapidly over the course of BP's forecast. Coal consumption, meanwhile, will broadly remain flat, with its share in primary energy declining to 21 percent -- the lowest share for coal since the industrial revolution.
"The energy mix by 2040 is the most diversified ever seen," according to BP.
In the power sector, however, coal will remain king.
Coal accounts for just 13 percent of the increase in power over the forecast period compared to more than 40 percent over the previous 25 years. Even so, it remains the largest source of energy for power generation in 2040, with a share of almost 30 percent.
Overall carbon emissions will also continue to rise through 2040, "signaling the need for a comprehensive set of actions to achieve a decisive break from the past."
If world leaders choose to take a different tack, the outcome could look very different.
California needs a sustainable and affordable energy system that can deliver an all-renewable energy supply and manage that supply cost-effectively.
Instead of creating an interstate entity that may not be aligned with California’s renewable energy goals, we should build an energy system that provides the modern grid California will actually need going into the future -- one that relies on coordinated local energy, modern grid operations, and balancing authorities to efficiently use the resources in our own backyard.
Regionalization is touted as a cost-saving effort that would bring renewable energy from across half the continent to California to even out the variability in energy production from renewables. But the call for regionalization ignores the tremendous progress that is already being made in utilizing clean local energy resources -- an approach that provides a trifecta of economic, environmental and resilience benefits, while avoiding the high costs in both dollars and governance associated with regionalization.
Theoretically, if the California Independent System Operator (CAISO) obtained energy from outside of the state when in-state renewable energy resources weren’t producing enough to meet California’s demand, California could meet its needs more cheaply than it would by building a lot more renewable energy plants. In principle, variability in renewable energy generation can be offset when resources are integrated over a wide enough area, because “the wind is always blowing somewhere.” However, the real question is whether regionalization is the most effective or cost-efficient approach to resolving these issues.
Regionalization would introduce new costs and risks. Relying on a continent-scale transmission grid would mean building many long transmission lines. Such continent-scale transmission is expensive and would unavoidably damage the environment it crosses.
Relying on distant energy sources increases vulnerability to disruptions across a larger grid. Operational error, extreme weather, natural disasters, and sabotage all pose greater risks with a large grid spanning the dry and fire-prone western region of North America.
In addition, without effective federal energy policy and emissions markets, regionalization could increase carbon emissions as existing renewables are dispatched from other states for California load, and coal plants in those states fill the gap. Meanwhile, investment in renewables projects in California would be suppressed, along with the associated jobs and revenues, as projects to serve California load are built out of state.
The economic risks are exacerbated by the fact that CAISO and California’s three big investor-owned utilities currently charge the same delivery fees for energy carried over hundreds of miles of expensive transmission lines as for energy delivered from down the street. This practice has already created distorted price signals that have led to inefficient markets, negatively impacted development and failed to contain the rapid rise in transmission costs. Using California ratepayer funds to subsidize energy imports and push development out of the state is not good policy.
Under some governance proposals for a regional transmission operator (RTO), California could become subject to the influence of coal state officials or utilities. California, which represents half of the population of the Western Electricity Coordinating Council area and over half of its economy, would have only a small fraction of the governance authority -- placing California’s leading efforts at risk should they conflict with regional policies.
Distributed energy resources (DERs) under a local balancing authority can meet these same needs more effectively -- without the downside risks that regionalization would bring.
First, the volatility and increasing complexity of the grid is happening in large measure at the distribution end of the grid, not the transmission end. Therefore, it should be managed first at the distribution level. All loads are local, and while local DERs can add complexity, they also allow loads to be locally managed and balanced, reducing volatility to the system overall.
Through a network of dedicateddistribution system operators (DSOs) to manage collections of DERs at the distribution level, aggregated DERs, such as solar-plus-storage and demand response, would use complementary local technologies to balance local load and generation, providing a well-behaved load profile to the transmission grid at the transmission-distribution interface. Thus, rather than looking to an ever-larger central grid to provide control, a DSO-based energy system can manage load and generation locally to integrate complementary renewable technologies and optimize use of the resources already in place.
Second, using local power and local balancing would contain the ever-increasing costs associated with expanding transmission. In California, transmission costs have been increasing faster than inflation for decades, even as the cost of generation has fallen.
Today, delivery charges threaten to surpass the cost of generation as the major cost of energy. This trend is likely to continue as long as utilities and community-choice aggregators are incentivized to procure remote generation. If the full costs of delivery are included in energy procurement -- by having transmission charges reflect the use of transmission infrastructure -- DERs can often provide energy more cheaply than remote generation, leading to overall cost savings for ratepayers.
Finally, DERs deliver greater reliability, because robust local generation from multiple sources is less subject to impacts from the failures of one or two components. For example, during the recent Thomas Fire emergency in Southern California, many of the areas that maintained power did so with microgrids including solar and storage resources, as regional transmission lines failed to deliver energy.
Transitioning our grid to a fully renewable energy system will require a mix of approaches. The foundation needs to be laid first at the local level with DERs managed by DSOs to make the transmission grid manageable. Some of this is already being done by the California Public Utilities Commission and local utilities. Only if it is determined that our needs will not be met with cost-effective local and in-state resources should we consider the costly infrastructure and legal commitments required to import energy.
This approach will ensure we rely on out-of-state resources only as needed, rather than creating a new entity that looks first to ultra-remote power as a solution. This DSO-based system of grid management would not create a regional ISO, but would instead supplement the existing and successful Energy Imbalance Market to incorporate a day-ahead market that would manage energy imports and exports for mutual benefit -- but without the deeper entanglements with coal states that will endanger our clean energy economy.
Ultimately, California needs an energy system that meets our clean energy goals primarily with local generation and solutions -- and one that looks to distant, expensive and potentially dirty energy only as a last resort. We should certainly use the transmission system we already have to help local balancing areas support one another, but we must consider all the costs and implications of increasing our reliance on distant resources and losing control of our energy future.
Doug Karpa is the policy director for Clean Coalition, a nonprofit organization with a mission to accelerate the transition to renewable energy and a modern grid.
The residential solar sector just saw an acquisition that, bucking a recent trend, had nothing to do with bankruptcy or retreat.
Solar equipment distributor Soligent acquired Repower America Wednesday, taking on the latter's network of local rooftop solar installers backed by a central support platform. The combined companies hope to fuel profitable solar growth across the nation by helping local installers do their job more effectively.
In recent years, the national, vertically integrated rooftop installers have largely gone out of business or faded from dominance (with the exception of Sunrun, which also leverages a network of installer partners). Smaller installers, known collectively as the long tail, are seeing more growth than the market leaders, and several platform plays have asserted a new theory of how to make money in this segment.
They posit that a cash-light startup can tackle the tasks that benefit from scale and software know-how, leaving the site visits and physical installation to the local workers who know the territory. In theory, this arrangement brings in more profit for both installer and platform company and provides a path for sustained solar growth.
"Everyone in the industry is realizing that a lot of the growth is coming from and will come from the long tail," said Allison Mond, an analyst at GTM Research covering the residential solar market. "Everyone’s trying to find how they can best partner with those companies and enable them to be successful."
Though nationwide expansion has thwarted the likes of SolarCity and Sungevity, Soligent CEO Jonathan Doochin thinks he can avoid the same pitfalls. He won't worry about trading profits for growth, because, he said, Soligent is already operating profitably in 50 states.
"We’re not saying when we reach 1 gigawatt of volume, then we’ll be lightweight," Doochin said, referencing the capital-light aspiration of solar companies past. "We're actually lightweight and profitable today."
Soligent runs a 39-year-old solar equipment distribution business serving some 5,000 installers. Repower America provides a "solar business in a box," training new installers in everything from marketing to selling, permitting and installing; it supports 200 companies and 50 franchises, which take on Repower branding and lead generation. Both are based in Northern California.
The merger will give Soligent's dealer partners access to higher levels of assistance, should they choose it. Instead of simply buying products, a Soligent customer can sign on for help with a single skill set like marketing or project management, or stack a few, or go the full-stack franchise route. This represents an expansion of the value chain that Soligent tackles.
Repower's existing customers will gain a partner with decades of experience delivering solar equipment. For Repower itself, this offers a shot at scaling that would have been much more difficult without a large corporate patron.
The news comes after a series of tough breaks for the residential sector, both internally and externally inflicted.
Over the past year, front-runner SolarCity cut back installations and lost its identity within Tesla; top-five installer Sungevity went bankrupt; and NRG Home Solar pulled out of the business, as did Direct Energy Solar.
In just the last month the industry reeled from import tariffs imposed by the Trump administration and the news that solar employment had declined for the first time since tracking began, a development very much related to the string of bankruptcies and uncertainty around the tariffs.
For Soligent's and Repower's leadership, that turbulence offered an opportunity to double down on their core thesis.
"We both believe in empowering the long tail and bringing them resources to be successful," Doochin said. "We see an opportunity with some of the larger, integrated businesses struggling to strengthen the tail."
Fortune hasn't been kind to rooftop solar in the past year. Soligent hopes to change that narrative. (Source: GTM Research report U.S. Residential Solar Finance)
Repower specializes in getting fresh-faced market entrants ready to do business within 90 days.
"We don’t see many competitors out there providing that," said CEO Mahesh Mansukhani.
The group will retain that training hub role at Soligent, but its responsibilities extend further, to the daily work of helping its franchises operate successfully.
The Repower America name will persist as a division within Soligent, the executives said, because membership in the national brand drives a lot of value for local installers. Its headquarters will move to Soligent's base in Petaluma.
The executives declined to disclose the terms of the acquisition. That said, it clearly wasn't a fire sale, and there was palpable excitement crackling in the conference room where they had gathered to discuss the news.
The combined companies will be able to offer a platform covering the full range of services an installer needs, Mansukhani said. That should give an edge over companies that provide few of the needed solutions, forcing installers to contract in several different places.
As it expands its volume nationally, Soligent won't face the same kinds of costs that made the vertically integrated plays untenable.
"If you look at SolarCity or others, they were betting on themselves installing and executing what is fundamentally a local business," said Repower COO Daniel Rubin. "We’re enabling the long tail. We’re not going to have trucks and install."
It's worth emphasizing that a platform play alone does not guarantee success.
Sungevity spent its final year touting a "capital-light" platform strategy; the venture-funded startup does the work that can scale, but avoids the costs of maintaining a fleet of workers across the nation. The company spent a few hundred million dollars before it could achieve that promise, and ultimately went bankrupt last March.
Others are trying their own versions, like Complete Solar, which makes it easier for sales teams and installers to specialize in their strengths without having to do everything.
If the "revenge of the long tail" thesis holds, the coming months will feature a land grab as the various platform companies race each other to bag new local partners.
Having one platform gain the resources of a large corporate parent may make it harder for smaller ones to compete. But then again, the nature of the long tail is that it's varied and vast; it won't be tapped out anytime soon.